When extracting a flow of production fluids such as oil, from a well, or injecting water into a well in secondary recovery methods of oil production, it is important to be able to measure the rate of fluid flow. In the case of oil production, it is also commonly desirable to determine the contribution to the overall flow recovered at the well head from different producing strata within the well. In multiple producing strata, it is desirable to know how much each stratum contributes to the total production of the well. Such information is useful, for example, as a matter of reservoir engineering to make determinations on the extent of reserves or, in the case where flow from a specific stratum is low, to consider taking remedial action such as fracturing in an effort to increase production from such a stratum.
Well bores are lined with casing whose approximate cross sectional area is known. The free internal cross sectional area of production tubing is also known. Accordingly it is possible to derive a measure of the volume of flow at a specific location by measuring the linear velocity of fluids flowing in the casing or piping.
The oil industry has utilized a variety of means of determining velocity of fluid flow. These include magnetic flow meters which depend upon the Faraday electromagnetic induction principle and which may be applied to fluids which are electrically conductive or contain charge carriers. Such meters operate by sensing electromotive force generated by induction in the flowing fluids in the presence of an imposed magnetic field.
Gamma ray meters are sometimes used where low flow-rate wells of less than 1,000 barrels of fluids per day are involved. Such meters require the injection of radioactive tracer elements into the flow stream, from which velocity is determined by timing the passage of such elements by gamma ray detectors that are disposed at known distance intervals along the conduit.
Obstructed flow meters constitute yet another class of flow measuring devices. Such meters employ orifices or other restrictions through which a portion of the fluid flow is directed, with the flow rate being functionally related to a pressure drop measured across the restriction. Obstructed flow meters depend on the Bernoulli principle and are generally restricted to compressible fluids.
In the past few years, a new type of flow meters has been developed based on a Coriolis principle. Fluids are passed through hollow tubes which are caused to vibrate in an angular harmonic oscillation. Due to the Coriolis forces, the tubes will deform and produce an additional vibration component, the presence of which is detected by sensors and is related to the rate of liquid flow within the conduit. The interpretation of signal results and the calibration of such meters can be complicated.
Ultrasonic or sonar meters represent a further type of flow meter. Such meters measure the difference of the transit time of sonic pulses propagated with and against the direction of fluid flow, from which difference the flow rate is determinable. The accuracy of such meters is a function of the physical properties of the fluid flow.
Thermal anemometry provides yet another principle upon which flow meters have been developed. Such meters operate by placing electrically heated probes within a flowing stream of fluid. The liquid flowing by and in contact with the probe causes a heat transfer from the probe to the liquid, which is sensed by measuring the current supplied to the probe to maintain a fixed or determinable temperature. The flow rate of the fluid is related to the amperage of the electrical power supplied to the probe.
The present invention employs a different type of flow metering device, a positive displacement meter. Positive displacement flow meters operate by counting known volumes of fluid (gas or liquid) that pass through the meter. Numerous designs exist for isolating and counting the throughput of liquid. One such form are impeller or turbine-type meters. Fluid flowing through a stationary impeller in the form of a multi-blade propeller or helical screw will cause the impeller to rotate. The angular speed of the impeller (or the number of its rotations) is related to the mass flow and/or linear speed of the fluid flowing within the conduit.
As may be imagined, the various types of meters have both advantages and disadvantages, and generally have applicability in differing specific downhole environments and liquid compositions, as the foregoing discussion has pointed out in broad terms. Ease of insertion of meters into the well; temperature and pressure, corrosiveness of the fluids present, and other environmental conditions within a well; reproducibility of results; accuracy; degree of complexity required to convert raw data and analyze data; and other factors all impact the choice of method and suitability of any given method.
Impeller based flow meters are well known in the art. Prior art impeller meters, however, have certain disadvantages. For example, in Basham and Cmelik, U.S. Pat. No. 4,345,480, impeller rotation direction and speed are sensed digitally by means of two light paths and a light interrupter means. Such a system requires light traveling from its source to the each of the sensing elements to traverse the fluid under measurement. In an oil well environment, where the fluids are usually opaque—as in many hydrocarbons—the sensing means may not be able to “see” the signal. Additionally, the '480 patent relies on downhole electrical circuitry that is both subject to potentially harsh temperature and pressures and requires electrical power to operate. Since wells frequently extend to depths of 25,000 feet or more, temperatures of over 150 degrees Celsius and pressures of 20,000 psi or more are typically present. Such ambient conditions impose rigid design requirements on electrical components. Additionally, power to operate the electronics must be provided from above ground with wiring dedicated to such a task.
The disclosure herein provides a new and unique improvement over the previously known designs. Because the sensing means employed in the present invention depends only on a generated magnetic flux field, passage of light through the measured fluid is not involved. Further, elements employed in the sensor do not involve in situ electronic circuitry the operability of which imposes difficult design criteria to withstand temperature and pressure extremes found in a wellbore environment. Nor does the invention require providing electrical power at the sensor. Finally, the systems and methods herein are fully optical fiber based, thereby avoiding any requirement to direct electrical wiring downhole. With the increasing use of optical fiber based systems for composition analysis of downhole fluids, location of casing collars and corrosion in well tubing and other well logging functions, it may be possible to multiplex the signals generated by the present system and methods on an existing optical fiber used for other purposes, thereby obviating a need for a separate signal line.